Nonionic surfactants for enhanced crude oil recovery

ABSTRACT

The present disclosure provides methods of using a nonionic surfactant for enhanced oil recovery, where the nonionic surfactant is prepared with a double metal cyanide catalyst. The present disclosure also provides for an emulsion that includes carbon dioxide, a diluent and the nonionic surfactant.

CLAIM OF PRIORITY

This application is a Divisional Application of U.S. application Ser.No. 14/347,143, filed Mar. 25, 2014 and published as U.S. PublicationNo. 2014-0251607, on Sep. 11, 2014, which claims benefit ofInternational Application Number PCT/US2012/056283, filed Sep. 20, 2012and published as WO 2013/048860 on Apr. 4, 2013, which claims thebenefit to U.S. Provisional Application 61/539,795, filed Sep. 27, 2011,the entire contents of which are incorporated herein by reference in itsentirety.

FIELD OF DISCLOSURE

Embodiments of the present disclosure are directed towards surfactants;more specifically, embodiments are directed towards nonionic surfactantsthat are soluble in carbon dioxide for enhanced crude oil recovery.

BACKGROUND

A variety of techniques have been used to enhance the recovery ofhydrocarbons from subterranean formations in which the hydrocarbons nolonger flow by natural forces. Such techniques can include waterinjection and/or subsequent miscible carbon dioxide flooding, amongothers. Water injection can be useful to recover some hydrocarbons,however, only about a third of the hydrocarbons are recovered using thistechnique. As such, typically water injection procedures are followed byan enhanced oil recovery technique such as miscible gas flooding.Miscible gas flooding can be performed with a carbon dioxide, to reducethe viscosity of the crude oil present in the subterranean formation inorder to increase the flow of hydrocarbons to a production well. Carbondioxide, which acts as a solvent to reduce the viscosity of the crudeoil, is one of the most effective, and least expensive, miscible gases.During the miscible carbon dioxide flooding procedure the carbon dioxideis typically in the liquid and/or supercritical phase.

Miscible carbon dioxide flooding, however, can be accompanied with anumber of drawbacks. One main problem encountered is poor sweep of thesubterranean formation. Poor sweep occurs when the gas injected into thereservoir during a miscible carbon dioxide flooding process flowsthrough the paths of least resistance due to the low viscosity of thegas, thus bypassing significant portions of the formation. When the gasbypasses significant portions of the formation, less crude oil iscontacted with the gas, reducing the likelihood that the gas will reducethe viscosity of the crude oil. Thus, the gas injected during themiscible carbon dioxide flooding process is meant to “sweep” the crudeoil toward the production well by lowering the viscosity of the crudeoil. However, when the gas does not contact a large portion of the crudeoil contained in the subterranean formation, a large portion of thecrude oil in the subterranean formation is left behind, producing poorsweep. In addition, due to the low density of the gas, the injected gascan rise to the top of the formation and “override” portions of theformation, leading to early breakthrough of the gas at the productionwell, leaving less gas within the subterranean formation to contact withthe crude oil, again reducing the likelihood that the gas will reducethe viscosity of the crude oil.

To enhance the effectiveness of the miscible carbon dioxide floodingprocess it has been suggested that a foaming agent or a surfactant beincluded in the process to help to generate a foam in the formation. Afoam can generate an apparent viscosity of 100 to 1,000 times that ofthe injected gas, therefore, the foam can inhibit the flow of the gasinto that portion of the subterranean formation that has previously beenswept. In other words, the foam can serve to block the volumes of thesubterranean formation through which the gas can short-cut, therebyreducing its tendency to channel through highly permeable fissures,cracks, or strata, and directing it toward previously unswept portionsof the subterranean formation. As such, the foam can force the gas todrive the recoverable hydrocarbons from the less depleted portions ofthe reservoir toward the production well.

The surfactants used in creating foams for miscible carbon dioxideflooding processes, however, have suffered from a number of drawbacks.For example, traditional surfactants, such as ethoxy-sulfates, cancreate emulsions of oil and water which are difficult to break. Theemulsions can cause permanent damage to the formation by irreversiblyplugging pore throats. Further, these emulsions when produced may bedifficult to separate or “break” and may necessitate costly solutions toremedy. Another problem encountered by prior art surfactants has beenthe selection of anionic surfactants that have a high affinity toformation rock within the reservoir, for example, carbonate. Surfactantswith a high affinity to formation rock can adsorb into the formationrock, leading to surfactant loss. Without the surfactant present, thereis less likelihood of forming foam within the reservoir, also leading toearly breakthrough and poor sweep, as discussed herein.

SUMMARY

Embodiments of the present disclosure include a nonionic surfactant, amethod of forming the nonionic surfactant and a method for recoveringcrude oil from a subterranean formation with the nonionic surfactant ofthe present disclosure.

The present disclosure provides for, among other things, a method forrecovering crude oil from a subterranean formation that is penetrated byat least one injection well and one production well, that includesinjecting a nonionic surfactant in carbon dioxide into the subterraneanformation, where the nonionic surfactant is prepared by an alkoxylationreaction with a double metal cyanide catalyst of a first epoxide, asecond epoxide different than the first epoxide, and a branchedaliphatic alcohol having 3 to 9 carbon atoms; and recovering crude oilfrom the subterranean formation from a production well. Injecting thenonionic surfactant can include creating a foam with the nonionicsurfactant in carbon dioxide and a diluent; and injecting the foam ofthe nonionic surfactant in carbon dioxide and the diluent into thesubterranean formation.

The nonionic surfactant can have a polydispersity of 1.01 to 1.10. Thebranched aliphatic alcohol can have 6 to 8 carbon atoms. The firstepoxide can be selected from the group consisting of propylene oxide,butylene oxide, hexene oxide, octene oxide, and combinations thereof.The second epoxide can be ethylene oxide. In one embodiment, the firstepoxide is propylene oxide and the second epoxide is ethylene oxide, anda first stage of the alkoxylation reaction adds the propylene oxide tothe branched aliphatic alcohol and a second stage of the alkoxylationreaction adds the ethylene oxide to provide the nonionic surfactant.

The nonionic surfactant can have propylene oxide as the first epoxide,where the alkoxylation reaction can have a molar ratio in a range of 1.5to 10 moles of propylene oxide per mole of branched aliphatic alcohol.The nonionic surfactant of the present disclosure can have ethyleneoxide as the second epoxide, where the alkoxylation reaction has a molarratio in a range of 1.5 to 40 moles of ethylene oxide per mole ofbranched aliphatic alcohol.

The nonionic surfactant of the present disclosure can be used as part ofa foam for use in enhanced crude oil recovery. An example of such a foamincludes the nonionic surfactant, carbon dioxide in a liquid orsupercritical phase, and a diluent, where the nonionic surfactantpromotes a formation of the foam formed of carbon dioxide and thediluent.

The present disclosure also includes a method of using a nonionicsurfactant prepared with a double metal cyanide catalyst for use inenhanced oil recovery, where the method includes providing the nonionicsurfactant prepared by an alkoxylation reaction with the double metalcyanide catalyst of a first epoxide, a second epoxide different than thefirst epoxide, and a branched aliphatic alcohol having 3 to 9 carbonatoms; and injecting the nonionic surfactant into a subterraneanformation during an enhanced oil recovery operation.

The above summary of the present disclosure is not intended to describeeach disclosed embodiment or every implementation of the presentdisclosure. The description that follows more particularly exemplifiesillustrative embodiments. In several places throughout the application,guidance is provided through lists of examples, and which examples canbe used in various combinations. In each instance, the recited listserves only as a representative group and should not be interpreted asan exclusive list.

DEFINITIONS

As used herein, “a,” “an,” “the,” “at least one,” and “one or more” areused interchangeably. The terms “comprises,” “includes” and variationsof these words do not have a limiting meaning where these terms appearin the description and claims. Thus, for example, a foam that comprises“a” nonionic surfactant can be interpreted to mean a foam that includes“one or more” nonionic surfactants. In addition, the term “comprising,”which is synonymous with “including” or “containing,” is inclusive,open-ended, and does not exclude additional unrecited elements or methodsteps.

As used herein, the term “and/or” means one, more than one, or all ofthe listed elements.

Also herein, the recitations of numerical ranges by endpoints includeall numbers subsumed within that range (e.g., 1 to 5 includes 1, 1.5, 2,2.75, 3, 3.80, 4, 5, etc.).

As used herein, the term “diluent” can include, for example, water,brine, connate water, surface water, distilled water, carbonated water,sea water and combinations thereof. For brevity, the word “diluent” willbe used herein, where it is understood that one or more of “water,”“brine,” “connate water,” “surface water,” “distilled water,”“carbonated water,” and/or “sea water” can be used interchangeably.

As used herein, a “surfactant” refers to a chemical compound that lowersthe interfacial tension between two liquids.

As used herein, a “dispersion” refers to a system in which particles ofany nature (e.g. solid, liquid or gas) are dispersed in a continuousphase of a different composition (or state). Examples of a dispersioncan include an emulsion and a foam.

As used herein, an “emulsion” refers to a mixture of two immiscibleliquids, where one liquid (the dispersed phase) is dispersed in theother (the continuous phase).

As used herein, a “foam” refers to a dispersion of a gas, liquid, orsupercritical fluid (where the phase may change depending on theconditions in the process) in a liquid.

As used herein, a “nonionic surfactant” refers to a surfactant where themolecules forming the surfactant are uncharged.

As used herein, “crude oil” refers to a naturally occurring, inflammableliquid consisting of a complex mixture of hydrocarbons of variousmolecular weights and other liquid organic compounds that are found insubterranean formations beneath the Earth's surface.

As used herein, a “supercritical phase” means a dense gas that ismaintained above its critical temperature (the temperature above whichit cannot be liquefied by pressure).

As used herein, a “cloud point” of a solution that includes the nonionicsurfactant of the present disclosure is the temperature at which thenonionic surfactant is no longer completely soluble, precipitating as asecond phase giving the solution a cloudy appearance.

BRIEF DESCRIPTION OF THE FIGURES

FIG. 1 provides a schematic of a Pressure-Volume-Temperature cell withan accumulator system for measuring cloud point values according to thepresent disclosure.

FIG. 2 provides cloud point pressures for Example 1 and ComparativeExample A of the nonionic surfactant of the present disclosure.

FIG. 3 provides cloud point pressures for Example 2 and ComparativeExample B of the nonionic surfactant of the present disclosure.

FIG. 4 provides a pressure drop versus time diagram for the ComparativeExample B and the nonionic surfactant of Example 2 of the presentdisclosure.

DETAILED DESCRIPTION

Embodiments of the present disclosure include a nonionic surfactant forenhanced crude oil recovery, the nonionic surfactant being prepared byan alkoxylation reaction with a double metal cyanide catalyst of a firstepoxide, a second epoxide different than the first epoxide, and abranched aliphatic alcohol having 3 to 9 carbon atoms. The nonionicsurfactant can be used as part of a foam for enhanced crude oilrecovery. The foam can include the nonionic surfactant, carbon dioxide(CO₂) in a liquid or supercritical phase, and a diluent, where thenonionic surfactant promotes a formation of the foam of the carbondioxide, the diluent and the nonionic surfactant.

Carbon dioxide is a poor solvent and, in general, only expensivenonionic surfactants containing such elements as fluorine and/or siliconare soluble in it. Unlike these expensive nonionic surfactants, thenonionic surfactant of the present disclosure is formed with a doublemetal cyanide (DMC) catalyst that allows for a nonionic surfactant thatis soluble in carbon dioxide at temperatures and pressure that aretypically found in subterranean formations undergoing enhanced crude oilrecovery. Examples of such temperatures and pressures for subterraneanformations include temperatures of 40 to 110° C. and pressures of 8300(1200 pounds per square inch (psi)) to 55000 (8000 psi) KPa.Surprisingly, the nonionic surfactants used in the present disclosurecan remain soluble in carbon dioxide at these lower pressures (e.g.,8300 kPa), which allows for their use in shallower subterraneanformations. In addition, the improved carbon dioxide solubility of thenonionic surfactants used in the present disclosure allows the nonionicsurfactant to remain in the carbon dioxide phase longer, therebyallowing the nonionic surfactant to travel deeper into the subterraneanformation.

For the various embodiments, carbon dioxide used in enhanced crude oilrecovery can be in a liquid, a gas or supercritical phase. Asappreciated by one skilled in the art, carbon dioxide is in a liquidphase when subjected to a pressure of 1072 pounds per square inch (psi)and a temperature below 31 degrees Celsius (° C.). In addition, thecarbon dioxide can transition to a supercritical phase when, at apressure of 1072 psi, the temperature rises above 31° C. In embodimentsof the present disclosure, the carbon dioxide injected into thesubterranean formation can be transferred through a pipeline where thepressure is 1400 psi to 3500 psi and temperature ranges from 25 to 90°C.

So, it is appreciated that the carbon dioxide used in enhanced crude oilrecovery processes may vacillate between one or more of a liquid phaseor a supercritical phase. As such, the nonionic surfactant, the diluentand the carbon dioxide form what can broadly be called a dispersion,which can encompass both a foam and/or an emulsion. For ease of reading,the term “foam” will be used in the present disclosure for consistency,but it is understood that at various points during its use the carbondioxide can be in different phases (e.g., liquid, gas, supercritical),therefore, the exact form of the dispersion formed with the nonionicsurfactant, the diluent and the carbon dioxide could be as a foam orcould be as an emulsion or something in between.

As discussed herein, an issue in enhanced crude oil recovery is thatcarbon dioxide injected directly into an underground formation has a lowviscosity, as a result of which it channels through high permeabilityzones in an oil reservoir and leaves much of the oil behind. So, insteadof spreading out through the underground formation, the carbon dioxidefinds the fastest way through the formation. If, however, the carbondioxide were made to behave in a more viscous manner, it could be madeto spread out and slow down thereby contacting more of the undergroundformation. This would lead to more contact of the carbon dioxide withthe crude oil in the underground formation.

To address this problem, the nonionic surfactant of the presentdisclosure helps to form a foam of carbon dioxide and the diluent. Thestructure of the nonionic surfactant helps to lower the interfacialtension between the carbon dioxide and the diluent, which helps increating the foam. When formed in the underground formation, the foamhelps to increase the residence time of the carbon dioxide and to spreadthe carbon dioxide through the underground formation. Once in contactwith the crude oil, the carbon dioxide can absorb into the crude oilmaking it less viscous, among other desirable properties.

For creating foams for conformance and mobility control in enhanced oilrecovery operations, it has been determined that it is preferable insome instances to inject the surfactant dissolved in the carbon dioxide.The nonionic surfactants of the present disclosure display a solubilityin carbon dioxide at the temperatures and pressures typically found insubterranean formations undergoing enhanced crude oil recovery.Surprisingly, nonionic surfactants of the present disclosure preparedwith a DMC catalyst, as compared to a potassium hydroxide catalyst,provide for a significant difference in carbon dioxide solubility.Specifically, a correlation of the catalyst used to prepare the nonionicsurfactants of the present disclosure and their solubility in carbondioxide (CO₂) has been found.

The nonionic surfactant of the present disclosure is prepared by analkoxylation reaction with a DMC catalyst of a first epoxide, a secondepoxide different than the first epoxide, and a branched aliphaticalcohol having 3 to 9 carbon atoms. As discussed herein, embodiments ofthe present disclosure utilize an aliphatic branched alcohol. Preferablythe aliphatic branched alcohol is acyclic and a monohydric primaryalcohol. Preferably, the aliphatic branched alcohol has 3 to 9 carbonatoms, and more preferably 6 to 8 carbon atoms. Using a mixture of thealiphatic branched alcohols to create the nonionic surfactants of thepresent disclosure is also possible. The choice of the number of carbonatoms used in the branched structure can be selected based on the enduse of the foam, especially the temperature and/or pressure of thesubterranean formation in which the foam will be used.

For the various embodiments, providing the nonionic surfactant caninclude an alkoxylation reaction having a first stage and a secondstage. The first stage includes alkoxylating the alcohol of thealiphatic branched alcohol with the first epoxide to provide anintermediate compound. The second stage includes alkoxylating theintermediate compound with the second epoxide, different than the firstepoxide, to form the nonionic surfactant. So, for example, in the firststage of the alkoxylation reaction the first epoxide can be added to thealcohol of the aliphatic branched alcohol in a blockwise fashion (ascompared to a random fashion), followed by a blockwise addition of thesecond epoxide. In other words, alkoxylating the alcohol of thealiphatic branched alcohol with the first epoxide forms a firsthomopolymer subunit (e.g., a first block) covalently attached to thealiphatic branched alcohol. This intermediate compound can then bealkoxylated with the second epoxide (a different epoxide structure thanthe first epoxide) to form a second homopolymer subunit (e.g., a secondblock) on the intermediate compound thereby forming the nonionicsurfactant of the present disclosure.

The alkoxylation reaction uses a DMC catalyst in both the first stageand the second stage of the alkoxylation reaction to produce thenonionic surfactant used in the present disclosure. A variety of DMCcatalysts can be used in the alkoxylation reactions. For example,suitable DMC catalysts can be prepared by reacting aqueous solutions ofmetal salts and metal cyanide salts or metal cyanide complex acids toform the DMC catalyst as a precipitate.

Examples of suitable DMC catalysts for the alkoxylation reaction of thepresent disclosure can be found, for example, in U.S. Pat. Pubs.2011/0083846 and 2005/0170991, among others, which are both incorporatedherein by reference. Specific examples of suitable DMC catalystsinclude, but are not limited to, ARCOL Catalyst 3, a DMC catalystavailable from Bayer Material Science AG (Leverkusen, Del.). Forcarrying out the reaction, the DMC catalyst can be added to the branchedalcohol. By means of reduced pressure (for example <100 mbar) and/or byincreasing the temperature (30 to 150° C.), water still present in themixture can be removed. Thereafter, inert conditions are establishedwith inert gas (e.g. nitrogen) and the first epoxide and then the secondepoxide are added in stages, as discussed herein, at temperatures offrom 60 to 180° C. Usually, 250 ppm to 1000 ppm of catalyst, based onthe mixture, is used for the alkoxylation reaction. Reaction times foreach step of the alkoxylation reaction can depend upon the degree ofalkoxylation desired as well as upon the rate of the alkoxylationreaction (which is, in turn, dependent upon temperature, pressure,catalyst quantity and nature of the reactants).

In the first stage of the alkoxylation reaction, the aliphatic branchedalcohol and the DMC catalyst are introduced into a reactor system andreacted under inert conditions (e.g., a nitrogen atmosphere). Thealcohol on the aliphatic branched alcohol reacts with the first epoxideto form an intermediate compound. The second epoxide is added to thereactor system during the second stage of the alkoxylation reaction,where the second epoxide, different than the first epoxide, reacts withthe intermediate compound in the presence of the catalyst and under theinert conditions to form the nonionic surfactant. The same DMC catalystcan be present in each of the alkoxylation reactions. If desired,additional catalyst can be added during the alkoxylation reaction.

For the present disclosure, the first epoxide is selected from the groupconsisting of propylene oxide, butylene oxide, hexene oxide, octeneoxide and combinations thereof. The second epoxide can be ethyleneoxide. As discussed, the second epoxide is different than the firstepoxide in forming the nonionic surfactant of the present disclosure.So, for example, when the first epoxide is propylene oxide, the secondepoxide cannot also be propylene oxide.

In a preferred embodiment, the first epoxide is propylene oxide and thesecond epoxide is ethylene oxide. For this embodiment, the first stageof the alkoxylation reaction adds the propylene oxide to the branchedaliphatic alcohol and the second stage of the alkoxylation reaction addsthe ethylene oxide to provide the nonionic surfactant. For example,during the first stage when the first epoxide is propylene oxide thealkoxylation reaction can have a molar ratio in a range of 1.5 to 10moles of propylene oxide per mole of branched aliphatic alcohol.Preferably, during the first stage when the first epoxide is propyleneoxide the alkoxylation reaction can have a molar ratio of propyleneoxide to the branched aliphatic alcohol in a range of 3:1.0 moles to7:1.0 moles. During the second stage when the second epoxide is ethyleneoxide the alkoxylation reaction has a molar ratio in a range of 1.5 to40 moles of ethylene oxide per mole of branched aliphatic alcohol.Preferably, during the second stage when the second epoxide is ethyleneoxide the alkoxylation reaction has a molar ratio in a range of 7 to 16moles of ethylene oxide per mole of branched aliphatic alcohol. Specificexamples of this second stage of the alkoxylation reaction include usinga molar ratio of ethylene oxide to branched aliphatic alcohol of 9:1moles or using a molar ratio of ethylene oxide to branched aliphaticalcohol of 14:1 moles.

The nonionic surfactant of the present disclosure provides a watersoluble component and a carbon dioxide soluble (water insoluble)component. While not wishing to be bound by theory, it is believed thatthe propylene oxide used in forming the nonionic surfactant, along withthe branched aliphatic alcohol, provides the carbon dioxide soluble(water insoluble) component of the nonionic surfactant, while theethylene oxide used in forming the nonionic surfactant provides thewater soluble component of the nonionic surfactant. To modify the carbondioxide and/or the water soluble portions, changes in the molar amountof the propylene oxide and ethylene oxide used in the nonionicsurfactant and/or the low molecular weight branched aliphatic alcoholused can be made.

For the surfactant to be soluble in carbon dioxide it is preferred thatthe aliphatic alcohol be branched, where being branched means thepresence of at least one branch (i.e., an oligomeric offshoot from amain chain) in the alkyl chain. While not wishing to be bound by theory,the presence of the branch in the alkyl chain is believed to lower theinteraction of the nonionic surfactants with each other (e.g.,preventing them from packing together) and thereby allowing strongersolvation of the surfactant by CO₂ molecules.

In addition, the alkoxylation reaction using the DMC catalyst providesthe nonionic surfactant used in the present disclosure with a narrowpolydispersity range. For the various embodiments, the nonionicsurfactant used in the present disclosure can have a polydispersity of1.01 to 1.10. The polydispersity can be determined by means of methodsknown to persons skilled in the art, for example by means of gelchromatography (size exclusion).

For the various embodiments, the nonionic surfactant of the presentdisclosure can have a cloud point in a range of the temperature of thesubterranean formation to 30° C. above a temperature of the subterraneanformation in which the foam is to be used. In some embodiments,selecting the nonionic surfactant of the present disclosure includesselecting the surfactant with a cloud point in a range of 10 to 20° C.above the temperature of the subterranean formation in which the foam isto be used.

Embodiments of the present disclosure include a method for recoveringcrude oil from a subterranean formation penetrated by at least oneinjection well and one production well. For the various embodiments, themethod includes providing the nonionic surfactant and injecting thenonionic surfactant in the carbon dioxide into the subterraneanformation via the injection well. For example, the diluent can beinjected into the formation followed by injection of the nonionicsurfactant with the carbon dioxide via the injection well to generatethe foam.

In an alternative example, it is also possible to inject the nonionicsurfactant with the diluent into the subterranean formation via theinjection well followed by injecting the carbon dioxide into thesubterranean formation (i.e., the carbon dioxide is injected after thenonionic surfactant with the diluent is injected into the subterraneanformation) to generate the foam. In addition, in some embodiments, thenonionic surfactant can be injected into the reservoir with both thediluent and carbon dioxide to generate the foam, where the nonionicsurfactant can be included in either the carbon dioxide and/or thediluent. The foam can also be created before being injected into thesubterranean formation by stirring the diluent and the nonionicsurfactant and injecting it into the subterranean reservoir. Othermethods of forming foam within a subterranean formation are described inU.S. Pat. No. 4,380,266, which is incorporated herein by reference.

For the various embodiments, the nonionic surfactant, as describedherein, can be included in an amount of at least 0.01 weight percentwhen dissolved directly in the carbon dioxide phase based on the weightof the carbon dioxide. In an additional embodiment, the nonionicsurfactant of the present disclosure can be present in an amount of atleast 0.05 weight percent when dissolved directly in the carbon dioxidephase based on the weight of the carbon dioxide. In another embodiment,the nonionic surfactant can be present in an amount of at least 0.5weight percent when dissolved directly in the diluent phase based on theweight of the diluent. In an additional embodiment, the nonionicsurfactant can be present in an amount of at least 1.0 weight percentwhen dissolved directly in the diluent phase based on the weight of thediluent. In addition, the nonionic surfactant can be included in thefoam of the present disclosure in a range of 0.03 to 5.0 weight percentbased on the total weight of the composition used to create the foam. Inanother embodiment, the nonionic surfactant can be included in thecompositions of the present disclosure in a range of 0.05 to 2.0 weightpercent based on the total weight of the composition used to create thefoam. Other ranges are possible.

The carbon dioxide is a noncondensable gas (e.g., a gas that is noteasily condensed by cooling) in the foam. As appreciated by one skilledin the art, for a given crude oil temperature, the noncondensable gascan become miscible with crude oil above a pressure known as the minimummiscibility pressure. Above this pressure, this “noncondensable” gas canattain a liquid phase or supercritical phase that has thecharacteristics of both gases and liquids. With enhanced recoveryprocesses which employ noncondensable gases under miscible conditionsthe crude oil can be caused to flow toward a producing well because thenoncondensable gas acts as a solvent, thus substantially dissolving, or“swelling” the crude oil (e.g., increases the volume of the crude oil bydissolving into the crude oil) to reduce the viscosity of the crude oil(e.g., provide a lowered viscosity of the crude oil). As used herein“dissolving” into the crude oil refers to the process where the carbondioxide in the foam passes into solution with the crude oil. Since thecarbon dioxide has a low viscosity relative to the crude oil, theviscosity of the crude oil will decrease as the carbon dioxide dissolvesinto the crude oil. In addition, viscosity is a measure of a fluid'sresistance to flow. Therefore, by allowing the carbon dioxide in thefoam to dissolve into the crude oil in the subterranean formation toprovide a lowered viscosity of the crude oil, the crude oil will flowmore readily than if the carbon dioxide had not dissolved into the crudeoil. By reducing the viscosity, the crude oil can flow into a productionwell linked to the subterranean formation for recovery of the crude oil.In other words, the crude oil, having the lowered viscosity, can berecovered from the subterranean formation from the production well.

Although embodiments described herein include carbon dioxide as thenoncondensable gas in compositions of the present disclosure, oneskilled in the art will appreciate that other noncondensable gases mayalso be included in place of carbon dioxide and/or in addition to carbondioxide. Examples of other possible noncondensable gases include, butare not limited to, nitrogen, natural gas, methane, propane, butane,ethane, ethylene, hydrogen sulfide, carbonyl sulfide, air, combustionflue gas, mixtures of methane with ethane, argon, light hydrocarbons,and mixtures thereof, among others.

The method for recovering crude oil from a subterranean formation canalso include injecting a drive fluid into the subterranean formationafter injection of the carbon dioxide and diluent to form the foam inthe subterranean formation. As used herein, the term “drive fluid” caninclude a liquid, a gas, a dispersion or a mixture thereof, which isused in enhanced crude oil recovery. Examples of a drive fluid caninclude, but are not limited to, water, brine, an aqueous solutioncontaining a polymer, a dispersion, a foam, an emulsion and mixturesthereof. Additional examples of the drive fluid can include a gas or avapor selected from carbon dioxide, H₂S, steam, a hydrocarbon-containinggas, an inert gas, air, oxygen and mixtures thereof. Further it isunderstood that the surfactant can be injected intermittently or usinggradients in concentration, which may help to lower the effective costof the application.

In some embodiments, compositions of the present disclosure can includeother additives. For example, the composition can include corrosioninhibitors, antioxidants, co-surfactants, scale inhibitors, mixturesthereof, as well as other additives. In some embodiments, the totalamount of the additives added to the compositions of the presentdisclosure is not greater than about 5 weight percent, based on a totalweight of the composition.

In addition to being used in enhanced crude oil recovery, the nonionicsurfactants of the present disclosure may also be used in a variety ofother areas where it would be desirable to use carbon dioxide as asolvent in a foam or an emulsion. Such areas include, but are notlimited to, dry cleaning applications and industrial catalysis. In drycleaning applications, the nonionic surfactant can help form an emulsionof water and supercritical carbon dioxide, which can act as a cleaningsolvent. In industrial catalysis, an emulsion or a foam of the nonionicsurfactant, supercritical carbon dioxide and a diluent may act as asolvent for the catalyst system, which normally would have required anorganic solvent.

It is to be understood that the above description has been made in anillustrative fashion, and not a restrictive one. Although specificembodiments have been illustrated and described herein, those ofordinary skill in the art will appreciate that other componentarrangements can be substituted for the specific embodiments shown. Theclaims are intended to cover such adaptations or variations of variousembodiments of the disclosure, except to the extent limited by the priorart.

In the foregoing Detailed Description, various features are groupedtogether in exemplary embodiments for the purpose of streamlining thedisclosure. This method of disclosure is not to be interpreted asreflecting an intention that any claim requires more features than areexpressly recited in the claim. Rather, as the following claims reflect,inventive subject matter lies in less than all features of a singledisclosed embodiment. Thus, the following claims are hereby incorporatedinto the Detailed Description, with each claim standing on its own as aseparate embodiment of the disclosure.

Embodiments of the present disclosure are illustrated by the followingexamples. It is to be understood that the particular examples,materials, amounts, and procedures are to be interpreted broadly inaccordance with the scope and spirit of the disclosure as set forthherein.

EXAMPLES

The following examples are given to illustrate, but not limit, the scopeof this disclosure. Unless otherwise specified, all instruments andchemicals used are commercially available.

Materials

Propylene Oxide (PO, The Dow Chemical Company)

Potassium hydroxide pellets (KOH, ACROS)

Sodium hydroxide (1 N NaOH, Fisher Scientific)

2-ethyl-1-hexanol (Sigma-Aldrich®, St. Louis, Mo.)

ARCOL Catalyst 3, Double Metal Cyanide catalyst (DMC catalyst) (BayerMaterial Science AG, Leverkusen, Del.).

Ethylene Oxide (EO, The Dow Chemical Company)

Magnesol®XL (Magnesium Silicate, The Dallas Group of America)

Hydranal® Composite 5 reagent (Fluka)

Deionized (DI) water is used throughout from a Nanopure™ II (Barnstead,Dubuque, Iowa) with an average conductance of 16 ohms.

Phthalic anhydride (JT Baker)

imidazole catalyst (Acros)

pyridine solvent (Fisher Scientific)

Nitrogen (Instrument-grade nitrogen (>99.99% pure, Praxair Distribution,Inc.)

Nonionic Surfactant Synthesis

The following procedure exemplifies a standard procedure forsynthesizing the nonionic surfactants of the present disclosure preparedby an alkoxylation reaction with a double metal cyanide catalyst of afirst epoxide, a second epoxide different than the first epoxide, and abranched aliphatic alcohol having 3 to 9 carbon atoms. One skilled inthe art will appreciate that this is an exemplary procedure and thatother branched aliphatic alcohol and/or different amounts of the firstepoxide and the second epoxide can be used in the procedure to make thenonionic surfactant of the present disclosure.

Size Exclusion Chromatography (SEC) Procedure

SEC experiments were performed identically for all samples. All sampleswere injected in duplicate to determine the standard deviation of themeasurement. The analysis conditions are given below:

Columns: A series of four Polymer Labs columns of the following sizes 50Å+100 Å+1000 Å+10000 Å are used, where all columns are 7.5×300 mm. The50 Å column is part number PL1110-6515; the 100 Å column is part numberPL1110-6520; the 1000 Å column is part number PL1110-6530 and the 10000Å column is part number PL1110-6540, all from Agilent, Santa Clara,Calif.

Pump and Autosampler: Waters 2695 HPLC system (Waters Corporation,Milford, Mass.).

Detector: Waters 2414 Differential Refractive Index (Waters Corporation,Milford, Mass.).

Eluent: tetrahydrofuran (uninhibited, HPLC grade, submicron filtered,Fisher Scientific, Waltham, Mass.).

Flow: 1 mL/min, Temperature: 40° C.

Injection: 100 μL.

Concentration: About 0.5% (w/v).

Calibration: PEG-10 polyethylene glycol standards (Agilent, Agilent,Santa Clara, Calif. Part number PL2070-0100).

Data system: Cirrus 3.2 (from Agilent, Santa Clara, Calif.).

Cloud Point Measurements in Super Critical Carbon Dioxide

Cloud point measurements in super critical carbon dioxide were performedwith a Temco Pendant drop Interfacial Tension IFT-820-P instrument(Temco, Inc. Tulsa Okla.), which was modified so that the IFT cell canprovide measurements of nonionic surfactant solubility in supercriticalcarbon dioxide (carbon dioxide held at or above its critical temperatureand critical pressure) at high pressures (up to 5000 psi) andtemperatures (up to 176° C.). The re-engineered cell is referred toherein as a Pressure-Volume-Temperature (PVT) cell. The PVT cellconsists of a small pressure vessel (42 mL volume), two heater bands,insulating jackets, and two high-pressure, tempered borosilicate glasswindows to facilitate viewing the interior of the cell. A diffuse lightsource was placed on one window to illuminate the interior of the cell,and a Ramé-Hart video microscope was used on the other window to takepictures of cell interior.

Since the PVT cell has a fixed volume, an accumulator was placed (1liter in volume) in line to the system to vary the pressure inside thePVT cell by pumping fluid to or from the accumulator in to the PVT cell.The accumulator was manufactured at OFI Testing Equipment, Inc.(Houston, Tex.). One side of the accumulator was connected to the PVTcell and was designed to hold liquid carbon dioxide, the other side wasplumbed up to DI water. A floating piston separates the two sides. Theaccumulator was housed inside a Blue M oven, model # DC-256-B-ST350(Thermal Product Solutions), so the entire accumulator could be heatedto the same temperature as the PVT cell. The tubing running from theaccumulator to the PVT cell was insulated to prevent heat loss. A HaskelMS-71 air driven liquid pump (Pneumatic and Hydraulic Co., Houston,Tex.) was used to adjust the pressure of the water side of theaccumulator, thereby adjusting the pressure inside the PVT cell. ATescom 6000 psi back pressure regulator (Emerson Process Management) wasinstalled on the water line to regulate the pressure of the water sideof the accumulator, and also to function as a relief valve safety deviceto prevent over-pressurization of the system. Lastly, a liquid carbondioxide feed line was added to the PVT/accumulator tubing system, withanother Haskel MS-71 air driven liquid pump to aid in pumping up theliquid carbon dioxide pressure in the system. The spring inside thisMS-71 pump was removed so the pump piston would operate more slowly toavoid flashing carbon dioxide inside the pump cavity. A schematic of thePVT setup with the accumulator system is shown in FIG. 1.

The total volume of the PVT cell, accumulator and all associated tubingwas estimated to be approximately 1050 milliliters (mL). The cell andtubing volume was estimated to be about 50 mL, while the accumulatorvolume was measured to be 1000 mL. For cloud point measurements, theaccumulator was filled with 500 mL of liquid carbon dioxide. At 20° C.the density of liquid carbon dioxide is approximately 0.774 g/mL. Thusthe total mass of carbon dioxide in the PVT cell system was calculatedto about 385 grams; 29.3 grams in the cell, and 355.7 grams in theaccumulator. Based on the total mass of carbon dioxide in the cell, thenonionic surfactant of the present disclosure was added to the system atapproximately 1000 parts per million (ppm). The requisite amount of thenonionic surfactant (approximately 0.385 g) addition was performed priorto filling the cell and accumulator with carbon dioxide. Out of the0.385 g, approximately 0.029 g was added in to the PVT cell and 0.356 gwas added in to the carbon dioxide side of the accumulator. If thesurfactant is solid, it was melted at 50° C. and then added in to thesystem. Before adding the carbon dioxide, the accumulator was pumpedfull of water to move the piston over to the carbon dioxide side to“zero” the volume. Surfactant was added to the tubing entering thecarbon dioxide side. 500 mL of water was drained from the water side ofthe accumulator so as to allow 500 mL of liquid carbon dioxide to enterthe carbon dioxide side and mix with the surfactant. A Haskel MS-71carbon dioxide feed pump was used to pressurize the entire system toapproximately 2300 psi before closing the carbon dioxide feed line. Atthis point the system was allowed to equilibrate for a few minutes toallow the surfactant to diffuse into the carbon dioxide phase, and forthe carbon dioxide to permeate into all the o-rings throughout thesystem.

The cell and oven temperatures were set at the lowest starting testtemperature (usually 40° C.) and the Haskel MS-71 water pump was used toincrease the system pressure until the interior of the cell wascompletely clear (usually about 2500 psi). The Ramé-Hart videomicroscope mounted in front of one borosilicate glass cell windowdisplays the cell interior on a computer screen. Alternately the cellinterior could be viewed via a mirror through the same window. Theopposite window was equipped with a light source for illuminating thecell interior for the camera.

The system was allowed to equilibrate for approximately 2 hours in thisstate in order to reach equilibrium at the temperature set point. Afterequilibration, the Tescom 6000 psi back pressure regulator was used onthe water line to slowly decrease the system pressure until thesurfactant began to precipitate out of solution. The pressure wasrecorded at which the first sign of precipitation was observed—this isreferred to as the cloud point of the surfactant at the giventemperature. Lower cloud point pressures indicate higher carbon dioxidesolubility of the nonionic surfactant at the given test temperature.

Synthesis of Examples 1 and 2 and Comparative Examples A and B

Perform the alkoxylation reactions in a jacketed, baffled 9 liter (L)stainless steel autoclave reactor equipped with magnetically drivenimpeller. Prior to each feed, charge alkylene oxide to a designated feed(DF) tank positioned on a weigh cell. Transfer alkylene oxide from theDF tank to the reactor through a flow meter at the reaction temperatureof 110 to 130° C.

Prepare two sets of surfactants: 2-ethyl-1-hexanol-(PO)₅-(EO)₉ (referredto herein as “EH-9”) and 2-ethyl-1-hexanol-(PO)₅-(EO)₁₃ (referred toherein as “EH-13”) using either a DMC catalysis (Example 1 and 2,respectively) or a KOH catalyst (Comparative Examples A and B). Thespecifics of the synthesis are as follows.

Comparative Examples A and B

Purge the 9 L reactor with nitrogen. Charge the 9 L reactor with 846.19grams of 2-ethyl-1-hexanol and add 3.47 grams of potassium hydroxidepellets. Vent the reactor seven times with nitrogen to removeatmospheric oxygen. Pressurize the rector with nitrogen to 16 to 20pounds per square inch absolute (psia) (103 to 138 KPa) at ambienttemperature (approximately 23° C.). Heat the reactor contents, withagitation, to 130° C. Meter 1780 grams of propylene oxide (P0) into thereactor over several hours at 130° C. After the PO feed is complete,agitate the reactor contents at reaction temperature (130° C.) toconsume unreacted oxide (digest) and then cool to 60° C.

Remove a portion of the reactor contents (144.1 g). Heat the remaining2463.9 g of reactor contents, with agitation, to 130° C. Meter 2140grams of ethylene oxide (E0) into the reactor over several hours. Afterthe E0 feed is complete, agitate the reactor contents at reactiontemperature (130° C.) to consume unreacted oxide, and then cool to 65°C. Neutralize the reactor contents by slurrying with magnesium silicate(Magnesol®XL, 200 g) and water (10 g) and filter to give ComparativeExample A, EH-9 formed with the KOH catalyst. A total of 3700 g ofComparative Example A was collected.

Comparative Example B was formed by repeating the synthesis ofComparative Example A, above, except 2157.0 grams of ethylene oxide (E0)was metered into the reactor over several hours. Neutralize the reactorcontents by slurrying with magnesium silicate (Magnesol®XL, 200 g) andwater (10 g) and filter to give Comparative Example B, EH-13 formed withthe KOH catalyst. A total of 3700 g of Comparative Example B wascollected.

The Comparative Example A (EH-9 formed with the KOH catalyst) andComparative Example B (EH-13 formed with the KOH catalyst) were testedfor carbon dioxide solubility using the PVT cell described herein (CloudPoint Measurements in Super Critical Carbon Dioxide). The cloud pointpressure for each of Comparative Example A and Comparative Example Bwere measured at 40° C., 60° C., and 80° C. The results are shown inTable 1, below.

Examples 1 and 2

Dehydrate 500 grams of 2-ethyl-1-hexanol (2-EH) in a rotary evaporatorunder partial vacuum (125-250 mm Hg) with a nitrogen sweep at 110° C.for 1 hour to reduce the water level below 250 ppm. Measure the watercontent at 165 ppm after dehydration by Karl Fisher titration. Slurry0.25 grams of ARCOL Catalyst 3 Double Metal Cyanide catalyst in thedehydrated 2-EH using an Ultra Turrax high speed mixer for one minute,then change into the 9 L pressure reactor, which has been nitrogenpurged.

Vent the reactor seven times with nitrogen to remove atmospheric oxygen.Pressurize the rector with nitrogen to 16 to 20 psia (103 to 138 KPa) atambient temperature (approximately 23° C.). Heat the reactor contents,with agitation, to 130° C. Meter 1120 grams of propylene oxide (PO) at 5to 7 grams per minute into the reactor over several hours at 130° C.After the PO feed is complete, agitate the reactor contents at reactiontemperature (130° C.) for an additional 2 hours to consume unreactedoxide (digest) and then cool to 60° C. A total of 123.2 grams ofreaction product was drained from the reactor leaving 1497.4 grams ofreaction product.

Heat the reactor contents with agitation to 130° C., and meter 1435grams of ethylene oxide (EO) into the reactor at 5 to 7 grams/minute.After the EO feed is complete, agitate the reactor contents at reactiontemperature (130° C.) for an additional 2 hours to consume unreactedoxide (digest), and then cool to 65° C. A total of 2653.10 g of Example1 was collected.

Example 2 was formed by repeating the synthesis of Example 1, above,except 2238 grams of ethylene oxide (EO) was metered into the reactor at5 to 7 grams/minute. A total of 3544 g of Example 2 was collected.

Example 1 (EH-9 formed with the DMC catalyst) and Example 2 (EH-13formed with the DMC catalyst) were analyzed for solubility insupercritical carbon dioxide as discussed above (Cloud PointMeasurements in Super Critical Carbon Dioxide). The cloud point pressurefor each of Example 1 and Example 2 were measured at 40° C., 60° C., and80° C. The results are shown in Table 1, below.

TABLE 1 Cloud pt at 40° Cloud pt at 60° Cloud pt at 80° Surfactant C.(psi) C. (psi) C. (psi) Example 1 1910 2675 3435 Example 2 1955 28803620 Comparative 2400 3410 4150 Example A Comparative 2120 3180 3920Example B

Table 2, below, shows the number average molecular weight (Mn (g/mol))and the weight average molecular weight (Mw (g/mol)), determined by theSEC, and the polydispersity of Examples 1 and 2 and Comparative ExamplesA and B.

TABLE 2 Mw/Mn Surfactant Mn (g/mol) Mw (g/mol) (polysidpersity) Example1 801 855 1.067 Example 2 1036 1087 1.049 Comparative Example A 786 9541.214 Comparative Example B 1046 1166 1.115

Cloud Point Pressures

FIGS. 2 and 3 show the cloud point pressures of Examples 1 and 2 andComparative Examples A and B in the supercritical carbon dioxide. Asillustrated in FIGS. 2 and 3, the cloud points show the solubility ofthe Example 1 (EH-9 formed with the DMC catalyst) and ComparativeExample A (EH-9 formed with the KOH catalyst), in FIG. 2, and Example 2(EH-13 formed with the DMC catalyst) and Comparative Example B (EH-13formed with the KOH catalyst) in supercritical carbon dioxide, in FIG.3, where above the cloud point pressure for a given temperature thenonionic surfactant is soluble in the supercritical carbon dioxide,whereas at or below the cloud point temperature the nonionic surfactantis insoluble in the supercritical carbon dioxide. As illustrated, thelower the pressure the more soluble the surfactant is in carbon dioxide.FIGS. 2 and 3 illustrates that the DMC catalyzed alkoxylate surfactantimproves carbon dioxide solubility relative the KOH catalyzed alkoxylatesurfactant.

Formation Response Testing

For formation response testing, as utilized for oil recovery methods,use a Model 6100 Formation Response Tester (FRT) (Chandler Engineering).The FRT measures the permeability changes of a formation sample whenexposed to a test fluid. The FRT simulates well completion andstimulation schedule on a core sample.

For the formation response testing use a single core holder containing asingle core (1.5″ inch diameter and 12″ long, Buff Berea sandstone,150-250 millidarcy air permeability, available from Kocurek Industries).Wrap the core in Saran™ wrap, then aluminum foil, and then placed insidea respective Aflas® 90 rubber sleeve which was then inserted into theHassler-type core holder. Apply a confining pressure of 3000 pounds persquare inch (psi) and a pressure of 1500 psi at the outlet of the corein the backpressure regulator. Heat the core to the desired temperaturebefore injecting fluids. Preheat the fluids to the core temperatureprior to injection to minimize heating and cooling effects in the core.Use a differential pressure transducer to measure pressure drop acrosscore up to 50 psi. Measure pressure drops exceeding 50 psi across thecore as a difference between the cell inlet and cell outlet pressuretransducers.

For each of Example 2 and Comparative Example B, saturate the core withthe surfactant by injecting about 25 ml of a 1 weight percent (wt. %)solution of the surfactant in brine (3% NaCl). Co-inject the brine,including 1 wt. % surfactant (flow rate: 0.1 milliliters/minute), andCO₂ (flow rate: 0.9 milliliters/minute) into the core to form theemulsion. Perform the experiments at room temperature (23° C.). Monitorthe pressure drop across the core for 26 hours.

FIG. 4 illustrates pressure drop versus time diagram for the surfactantof Comparative Example B and the nonionic surfactant of Example 2. Theincrease in pressure drop over time for both surfactants indicatesformation of emulsion in the core. The pressure drops are similar forboth surfactants indicating that similar foam strength is obtained whileusing either DMC or KOH catalyzed surfactants.

In the foregoing Detailed Description, various features are groupedtogether in exemplary embodiments for the purpose of streamlining thedisclosure. This method of disclosure is not to be interpreted asreflecting an intention that any claim requires more features than areexpressly recited in the claim. Rather, as the claims reflect, inventivesubject matter lies in less than all features of a single disclosedembodiment. Thus, the claims are hereby incorporated into the DetailedDescription, with each claim standing on its own as a separateembodiment of the disclosure.

What is claimed:
 1. A method for recovering crude oil from asubterranean formation that is penetrated by at least one injection welland one production well, comprising: injecting a nonionic surfactant incarbon dioxide into the subterranean formation, where the nonionicsurfactant has a polydispersity of 1.01 to 1.10 and is prepared by analkoxylation reaction with a double metal cyanide catalyst where in afirst stage of the alkoxylation reaction a first epoxide selected fromthe group consisting of propylene oxide, butylene oxide, hexane oxide,octene oxide and combinations thereof reacts with a branched aliphaticalcohol having up to 9 carbon atoms to form an intermediate compoundthat reacts in a second stage of the alkoxylation reaction with a secondepoxide different than the first epoxide, the second epoxide selectedfrom the group consisting of ethylene oxide, propylene oxide, butyleneoxide, hexane oxide, octene oxide and combinations thereof; creating afoam with the nonionic surfactant in carbon dioxide and a diluent; andrecovering crude oil from the subterranean formation from a productionwell.
 2. The method of claim 1, where the branched aliphatic alcohol has6 to 8 carbon atoms.
 3. The method of claim 1, where the first epoxideis propylene oxide and the second epoxide is ethylene oxide.
 4. Themethod of claim 1, where the first epoxide is propylene oxide and thealkoxylation reaction has a molar ratio in a range of 1.5 to 10 moles ofpropylene oxide per mole of branched aliphatic alcohol.
 5. The method ofclaim 1, where the second epoxide is ethylene oxide and the alkoxylationreaction has a molar ratio in a range of 1.5 to 40 moles of ethyleneoxide per mole of branched aliphatic alcohol.
 6. A method for recoveringcrude oil from a subterranean formation, comprising: injecting anonionic surfactant in carbon dioxide into a subterranean formation,where the nonionic surfactant is prepared by an alkoxylation reactionwith a double metal cyanide catalyst where in a first stage of thealkoxylation reaction a first epoxide selected from the group consistingof propylene oxide, butylene oxide, hexane oxide, octene oxide andcombinations thereof reacts with a branched aliphatic alcohol having upto 9 carbon atoms to form an intermediate compound that reacts in asecond stage of the alkoxylation reaction with a second epoxidedifferent than the first epoxide, the second epoxide selected from thegroup consisting of ethylene oxide, propylene oxide, butylene oxide,hexane oxide, octene oxide and combinations thereof; and recoveringcrude oil from the subterranean formation.
 7. The method of claim 6further comprising forming a foam with the nonionic surfactant in carbondioxide and a diluent.
 8. The method of claim 7, wherein the carbondioxide comprises supercritical carbon dioxide.
 9. The method of claim7, wherein the carbon dioxide comprises liquid carbon dioxide.
 10. Themethod of claim 7, wherein the carbon dioxide comprises gaseous carbondioxide.
 11. A method for recovering crude oil from a subterraneanformation, comprising: injecting a nonionic surfactant in anoncondensable gas into a subterranean formation, where the nonionicsurfactant is prepared by an alkoxylation reaction with a double metalcyanide catalyst where in a first stage of the alkoxylation reaction afirst epoxide selected from the group consisting of propylene oxide,butylene oxide, hexane oxide, octene oxide and combinations thereofreacts with a branched aliphatic alcohol having up to 9 carbon atoms toform an intermediate compound that reacts in a second stage of thealkoxylation reaction with a second epoxide different than the firstepoxide, the second epoxide selected from the group consisting ofethylene oxide, propylene oxide, butylene oxide, hexane oxide, octeneoxide and combinations thereof; and recovering crude oil from thesubterranean formation.
 12. The method of claim 11, wherein thenoncondensable gas is selected from carbon dioxide, nitrogen, naturalgas, methane, propane, butane, ethane, ethylene, hydrogen sulfide,carbonyl sulfide, air, combustion flue gas, mixtures of methane withethane, argon, light hydrocarbons, and mixtures thereof.
 13. The methodof claim 11, further comprising injecting a drive fluid into thesubterranean formation.